Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms a reservoir in which hydrocarbons are able to collect. A well is drilled through the earth until the hydrocarbon is bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.
In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. As the drilling progresses downward, the drill string is extended by adding more pipe sections.
A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As a well bore is drilled deeper and passes through hydrocarbon producing formations, however, the production of hydrocarbons must be controlled until the well is completed and the necessary production equipment has been installed. The drilling fluid also is used to provide that control. That is, the hydrostatic pressure of drilling fluid in the well bore relative to the hydrostatic pressure of hydrocarbons in the formation is adjusted by varying the density of the drilling fluid, thereby controlling the flow of hydrocarbons from the formation.
When the drill bit has reached the desired depth, larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. The casing then is perforated at the level of the oil bearing formation so oil can enter the cased well. If necessary, various completion processes are performed to enhance the ultimate flow of oil from the formation. The drill string is withdrawn and replaced with a production string. Valves and other production equipment are installed in the well so that the hydrocarbons may flow in a controlled manner from the formation, into the cased well bore, and through the production string up to the surface for storage or transport.
This simplified drilling process, however, is rarely possible in the real world. For various reasons, a modern oil well will have not only a casing extending from the surface, but also one or more pipes, i.e., casings, of smaller diameter running through all or a part of the casing. When those “casings” do not extend all the way to the surface, but instead are mounted in another casing, they are referred to as “liners.” Regardless of the terminology, however, in essence the modern oil well typically includes a number of tubes wholly or partially within other tubes.
Such “telescoping” tubulars, for example, may be necessary to protect groundwater from exposure to drilling mud. A liner can be used to effectively seal the aquifer from the borehole as drilling progresses. Also, as a well is drilled deeper, especially if it is passing through previously depleted reservoirs or formations of differing porosities and pressures, it becomes progressively harder to control production throughout the entire depth of the borehole. A drilling fluid that would balance the hydrostatic pressure in a formation at one depth might be too heavy or light for a formation at another depth. Thus, it may be necessary to drill the well in stages, lining one section before drilling and lining the next section. Portions of existing casing also may fail and may need to be patched by installing liners within damaged sections of the casing.
The traditional approach to installing a liner in an existing casing has been to connect or “tie” the liner into an anchor, that is, a “liner hanger.” Conventional anchors have included various forms of mechanical slip mechanisms that are connected to the liner. The slips themselves typically are in the form of cones or wedges having teeth or roughened surfaces. The typical hanger will include a relatively large number of slips, as many as six or more. A running and/or setting tool is used to position the anchor in place and drive the slips from their initial, unset position, into a set position where they are able to bite into and engage the existing casing. The setting mechanisms typically are either hydraulic, which are actuated by increasing the hydraulic pressure within the tool, or mechanical, which are actuated by rotating, lifting, or lowering the tool, or some combination thereof.
Such mechanical slip hangers may be designed to adequately support the weight of long liners. In practice, however, the wedges, cones, and the like that are intended to grip the existing casing may partially extend as the tool is run through existing casing and can cause the hanger to get stuck. They also may break off and interfere with other tools already in the well or make it difficult to run other tools through the casing at a later time. Moreover, separate “packers” must be used with such anchors if a seal, is required between the liner and the existing casing.
One approach to avoiding such problems has been to eliminate in a sense the anchor entirely. That is, instead of tying a liner into an anchor, a portion of the liner itself is expanded into contact with an existing casing, making the liner essentially self-supporting and self-sealing. Thus, the liner conduit is made of sufficiently ductile metal to allow radial expansion of the liner, or more commonly, a portion of the liner into contact with existing casing. Various mechanisms, both hydraulic and mechanical, are used to expand the liner. Such approaches, however, all rely on direct engagement of, and sealing between the expanded liner and the existing casing.
For example, U.S. Pat. No. 6,763,893 to B. Braddick discloses a patch liner assembly that is used, for example, to repair existing casing. The patch assembly comprises a pair of expandable conduits, that is, an upper expandable liner and a lower expandable liner. The expandable liners are connected to the ends of a length of “patch” conduit. The patch assembly is set within the casing by actuating sets of expanding members that radially expand a portion of each expandable liner into engagement with the casing. Once expanded, the expanded portion of the liners provide upper and lower seals that isolate the patched portion of the existing casing. The expanded liners, together with the patch conduit, thereafter provide a passageway for fluids or for inserting other tubulars or tools through the well.
U.S. Pat. No. 6,814,143 to B. Braddick and U.S. Pat. No. 7,278,492 to B. Braddick disclose patch liner assemblies which, similar to Braddick '893, utilize a pair of expandable liners connected via a length of patch conduit. The upper and lower liners are expanded radially outward via a tubular expander into sealing engagement with existing casing. Unlike the expanding members in Braddick '893, however, the tubular expanders disclosed in Braddick '143 and '492 are not withdrawn after the liner portions have been expanded. They remain in the expanded, set liner such that they provide radial support for the expanded portions of the liner.
U.S. Pat. No. 7,225,880 to B. Braddick discloses an approach similar to Braddick '143 and '492, except that it is applied in the context of extension liners, that is, a smaller diameter liner extending downward from an existing, larger diameter casing. An is expandable liner is expanded radially outward into sealing engagement with the existing casing via a tubular expander. The tubular expander is designed to remain in the liner and provide radial support for the expanded liner.
U.S. Pat. No. 7,387,169 to S. Harrell et al. also discloses various methods of hanging liners and tying in production tubes by expanding a portion of the tubular via, e.g., a rotating expander tool. All such methods rely on creating direct contact and seals between the expanded portion of the tubular and the existing casing.
Such approaches have an advantage over traditional mechanical hangers. The external surface of the liner has no projecting parts and generally may be run through existing conduit more reliably than mechanical liner hangers. Moreover, the expanded liner portion not only provides an anchor for the rest of the liner, but it also creates a seal between the liner and the existing casing, thus reducing the need for a separate packer. Nevertheless, they suffer from significant drawbacks.
First, because part of it must be expandable, the liner necessarily is fabricated from relatively ductile metals. Such metals typically have lower yield strengths, thus limiting the amount of weight and, thereby, the length of liner that may be supported in the existing casing. Shorter liner lengths, in deeper wells, may require the installation of more liner sections, and thus, significantly greater installation costs. This problem is only exacerbated by the fact that expansion creates a weakened area between the expanded portion and the unexpanded portion of the liner. This weakened area is a potential failure area which can damage the integrity of the liner.
Second, it generally is necessary to expand the liner over a relatively long portion in order to generate the necessary grip on the existing casing. Because it must be fabricated from relatively ductile metal, once expanded, the liner portion tends to relax to a greater degree than if the liner were made of harder metal. This may be acceptable when the load to be supported is relatively small, such as a short patch section. It can be a significant limiting factor, however, when the expanded liner portion is intended to support long, heavy liners.
Thus, some approaches, such as those exemplified by Braddick '143 and '492, utilize expanders that are left in the liner to provide radial support for the expanded portion of the liner. Such designs do offer some benefits, but the length of liner which must be expander still can be substantial, especially as the weight of the liner string is increased. As the length of the area to be expanded increases the forces required to complete the expansion generally increase as well. Thus, there is progressively more friction between the expanding tool and the liner being expanded and more setting force is required to overcome that increasing friction. The need for greater setting forces over longer travel paths also can increase the chances that liner will not be completely set.
Moreover, the liner necessarily must have an external diameter smaller than the internal diameter of the casing into which it will be inserted. This clearance, especially for deep wells where a number of progressively smaller liners will be hung, preferably is as small as possible so as to allow the greatest internal diameter for the liner. Nevertheless, if the tool is to be passed reliably through existing casing, this clearance is still relatively large, and therefore, the liner portion is expanded to a significant degree.
Thus, it may not be possible to fabricate the liner from more corrosion resistant alloys. Such alloys typically are harder and less ductile. In general, they may not be expanded, or expanded only with much higher force, to a degree sufficient to close the gap and grip the existing casing.
Another reality facing the oil and gas industry is that most of the known shallow reservoirs have been drilled and are rapidly being depleted. Thus, it has become necessary to drill deeper and deeper wells to access new reserves. Many operations, such as mounting a liner, can be practiced with some degree of error at relatively shallow depths. Similarly, the cost of equipment failure is relatively cheap when the equipment is only a few thousand feet from the surface.
When the well is designed to be 40,000 feet or even deeper, such failures can be to costly in both time and expense. Apart from capital expenses for equipment, operating costs for modern offshore rigs can be $500,000 or more a day. There is a certain irony too in the fact that failures are not only more costly at depth, but that avoiding such failures is also more difficult. Temperature and pressure conditions at great depths can be extreme, thus compounding the problem of designing and building tools that can be installed and will function reliably and predictably.
In particular, hydraulic actuators are commonly employed in downhole tools to generate force and movement, especially linear movement within the tool as may be required to operate the tool. They typically include a mandrel which is connected to a work string. A stationary piston is connected to the mandrel, and a hydraulic cylinder is mounted on, and can slide over the mandrel and the stationary piston. The stationary piston divides the interior of the cylinder into two hydraulic chambers, a top chamber and a bottom chamber. An inlet port allows fluid to flow through the mandrel into the bottom hydraulic chamber, which in turn urges the cylinder downward and away from the stationary piston. As the cylinder moves downward, fluid is able to flow out of the top hydraulic chamber via an outlet port. The movement of the cylinder then may be used to actuate other tool components.
Hydraulic actuators, therefore, can provide an effective mechanism for creating relative movement within a tool, and they are easily actuated from the surface simply by increasing the hydraulic pressure within the tool. Such actuators, however, can be damaged by the hostile environment in which they must operate. The hydrostatic pressures encountered in a well bore can be extreme and imbalances between the pressure in the mandrel and outside the actuator are commonly encountered. If the ports are closed while the tool is being run into a well, such pressure differentials will not cause unintended movement of the actuator, but they can impair subsequent operation of the actuator by deforming the actuator cylinder. Such problems can be avoided by immobilizing the cylinder through other means and simply leaving the ports open to avoid any imbalance of hydrostatic pressure that might deform the actuator cylinder. Fluids in a well bore, however, typically carry a large amount of gritty, gummy debris. The ports and hydraulic chambers in the actuator, therefore, typically are filled with heavy grease before they are run into the well. Nevertheless, the tool may be exposed to wellbore fluid for prolonged periods and under high pressure, and debris still can work its way into conventional actuators and impair their operation.
The increasing depth of oil wells also means that the load capacity of a connection between an existing casing and a liner, whether achieved through mechanical liner hangers or expanded liners, is increasingly important. Higher load capacities may mean that the same depth may be reached with fewer liners. Because operational costs of running a drilling rig can be so high, significant cost savings may be achieved if the time spent running in an extra liner can be avoided.
Ever increasing operational costs of drilling rigs also has made it increasingly important to combine operations so as to reduce the number of trips into and out of a well. For example, especially for deep wells, significant savings may be achieved by drilling and lining a new section of the well at the same time. Thus, tools for setting liners have been devised which will transmit torque from a work string to a liner. A drill bit is attached to the end of the liner, and the liner is rotated.
Torque is typically transmitted through the tool by a series of tubular sections threaded together via threaded connectors. The rotational forces transmitted through the tool, however, can be substantial and can damage threaded connections by over-tightening the threads. In addition, it often is useful to rotate opposite to the threads. Such reverse, or “left-handed” rotation may be useful in the actuation and operation of various mechanisms, but it can loosen the connection. In either event, if connections in the torque transmitting components are impaired, it may be difficult or impossible to operate the tool. Set screws, pins, keys, and the like, therefore, have been used to secure a connector, but such approaches are susceptible to failure.
Such disadvantages and others inherent in the prior art are addressed by the subject invention, which now will be described in the following detailed description and the appended drawings.